pacific northwest lng

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Pacific NorthWest LNG

Environmental Impact Statement and Environmental Assessment Certificate ApplicationSection 2: Project Description

February 2014Project No. 1231-10537

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2 PROJECT DESCRIPTION

2.1 Environmental Design A site selection and detailed feasibility study (DFS) for a shale gas-to-LNG project by thepredecessors of PNW LNG began in October 2011. Following the DFS and conclusion of feasibilityassessment agreement (FAA) with PRPA, a pre-front end engineering design (pre-FEED) programwas launched with the focus to better define the baseline conditions of the site, which includedpreliminary marine and terrestrial geotechnical investigation. In May 2013, the front end engineeringdesign (FEED) program was launched and carried out in parallel with certain pre-FEED activities,including geotechnical and environmental investigations.

In an effort to select the best engineering design, PNW LNG is carrying out three simultaneousFEEDs by three independent world-class teams of LNG engineering companies. One of these teamswill be selected to execute the engineering, procurement, construction and commissioning (EPCC)phase following positive final investment decision (FID) expected in late 2014.

Section 2.4 elaborates on the site selection process, and the following sections describe projectcomponents and activities that have been refined from DFS to pre-FEED, and the on-going FEEDphase.

2.1.1 Project Design Philosophies

PNW LNG places the utmost importance on environmental performance and stakeholder feedbackto achieve a sustainable Project. As such, in addition to typical design philosophies, PNW LNG hasprovided the following philosophies to the competing FEED teams as guiding principles.

2.1.1.1 Reducing GHG Emissions

PNW LNG design philosophy focuses on reducing GHG emissions by adapting engineering solutionsthat meet the BC BAT policy. PNW LNG is also expecting FEED contractors to benchmark theemission figures for their design with other LNG projects. GHG emissions will be measured as ratioof carbon dioxide equivalent (CO2e) emission against production.

Preliminary design indicates PNW LNG will be able to achieve 0.27 tonnes of CO2e (tCO2e) pertonne LNG production, or better. This ratio is below the industrial average of 0.33 tCO2e per tonneLNG production for twelve LNG export facilities currently proposed worldwide, and very close to thebest of all projects proposed (0.25 t CO2e/t LNG ). This performance could be achieved by usinghigh efficiency aero-derivative gas turbines that need less fuel and generate less GHG emissions,reducing energy consumption by applying state-of-the-art waste heat recovery systems, andreducing fugitive GHG emissions.

2.1.1.2 Use of Novel Technologies

PNW LNG has qualified several technologies for use in the Project. This allows the Project to adoptsafe, practical and cost effective advanced technologies to enhance plant efficiency.


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2.1.1.3 Plant Layout Master Planning

The plant layout master planning takes into account local topography, environmental issues andarchaeological values (e.g., culturally modified trees) of Lelu Island. Additional details on layout

alternatives are discussed in Section 2.4.

2.1.1.4 Venting and Flaring Philosophy

PETRONAS adopts zero venting and flaring philosophy during normal operations. This philosophy isfully extended to PNW LNG operations.

2.1.2 Project Design Standards and Policies

The following is the hierarchy of design codes and standards for the Project:

a) Canadian and BC laws and their supporting regulations

b) Canadian and BC codes and standards

c) PETRONAS technical standards (PTS)d) International codes and standards

e) Contractor’s design codes and standards.

2.1.2.1 Canadian and BC Laws, Regulations, Codes and Standards

Design and construction of the Project is subject to a range of Canadian and BC laws, regulations,codes and standards. The CSA Standard Z276-11 on LNG production storage and handling is a keydesign standard for the Project.

Liquefied Natural Gas - Production, Storage, and Handling (CSA Z276-11)

This Standard “establishes essential requirements and minimum standards for the design,installation, and safe operation of liquefied natural gas (LNG) facilities”. The Standard applies to allstages and aspects of the Project, excluding transportation of LNG and other gases (refrigerants,feed gas) beyond any loading or transportation interconnects.

As well as providing information related to normal operations of an LNG facility, the Standard alsodescribes requirements for upset conditions, including design spills, seismic design, fire exposure,emergency procedures.

2.1.2.2 PETRONAS Technical Standards

Because PNW LNG is a subsidiary of PETRONAS, the Project is subject to PETRONAS technicalstandards (PTS), which covers a wide range of project activities and components. The PTS is a

collection of standards developed to supplement international standards and updated withPETRONAS’ operating experience over several decades. PTS provides corporate guidance forengineering design; and health, safety and environment (HSE) for all facilities in the PETRONASGroup.

Some key health, safety and environment PTS relevant to the Project are described in the followingsubheadings.


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Environmental Impact Statement and Environmental Assessment Certificate Application

Section 2: Project Description

February 2014

Project No. 1231-10537 2-3

Air Emission Management

This standard describes consistent processes and criteria for air emission management. This

includes information on sources identification and inventory development; emission factors; best

available techniques (BAT) for air emission control; and monitoring and performance reporting.

Greenhouse Gas (GHG) Monitoring, Reporting and Verification

This standard describes identifying GHG sources, selecting reporting boundaries, and monitoring

(and reporting) of GHG emissions. It also provides guidance for developing verification procedures to

meet international standards such as ISO 14064-3 (Greenhouse Gases—Part 1: Specification with

guidance at the organizational level for quantification and reporting of greenhouse gas emissions

and removals).

Wastewater Management

This standard describes effective management of discharges from project sites. It provides guidance

for developing consistent processes and criteria for managing wastewater, as well as reducingenvironmental risks associated with wastewater and storm water discharges. Detail is provided on

process water, sewage, water treatment, and water purification plants.

Waste Management

This standard describes handling, collecting, transferring, transporting, treating and disposing of

waste. It is used to develop site-specific waste management plans, with specific reference to local

regulatory requirements and international conventions such as the Basel Convention on the Control

of Transboundary Movements of Hazardous Waste and their Disposal and MARPOL.

Environmental Incident Prevention and Control Implementation (EIPC)

Incident management is an essential part of PETRONAS’s HSE Management System. This standard

outlines the process for developing a EIPC management plan, including hazard identification and risk

assessment, effects identification, management planning, program implementation, and audits and

reviews. It provides detailed guidance for quantitative risks assessments and development of

mitigation and emergency response strategies.

Spill Contingency Planning

The Spill Contingency Planning standard applies to all loss of containment of liquid hydrocarbons or

hydrocarbon-based substances—this includes LNG spills. This standard details expectation for site-

specific response plans (including liaison with government agencies) and outlines the structures for

response teams and processes to be detailed in a site-specific plan.

Decommissioning, Remediation and Reclamation of On-shore E & P Sites

These standards provide the steps for planning and implementing decommissioning, remediation

and reclamation (DPR) programs. They outline a phased approach to DPR, and they provide

guidance on DPR for various types of facilities, including access roads, camp sites, gas treatment

and storage facilities, pipelines, waste disposal and/or treatment sites, pits, ponds and dumps.


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2.1.3 Project Design Mitigation and Changes

The engineering philosophy for the Project is to design for reduced environmental effects and tocontinue to reduce the potential for environmental effects from the Project during each phase of

engineering design. As the project design has matured from DFS to pre-FEED and into FEED, PNWLNG has received more input from stakeholders and has incorporated mitigation measures within thedesign.

2.1.3.1 Project Location

The alternatives assessment process for site selection are provided in Section 2.4.5. The decisionwas made to locate the Project on port lands designated for industrial use and marine export, asidentified in the PRPA LUMP (see Section 1.6). By siting the facility in an area designated for theseuses, the Project avoids disturbing lands not intended for industrial uses.

2.1.3.2 Bridge Location and Design

The bridge between Lelu Island and the mainland will be sited to reduce potential environmental effectsin Lelu Slough related riparian zones (Section 2.4.4). The bridge has been designed to allow vesselsup to the size of gill-netters to pass beneath (clearance of approximately 11 m above high water).

2.1.3.3 Marine Infrastructure Location

As discussed in detail in Alternative Means of Carrying Out the Project (Section 2.4.6), the locationand design of the marine infrastructure (trestle, berths and material off-loading facility [MOF]) havebeen designed to reduce the effects of navigational barriers and habitat disturbance. Specifically, thetrestle avoids core eelgrass habitat on Flora Bank (see Section 13) and allows the free movement oftides and currents through and between the pipe pile-trestle supports.

2.1.3.4 Marine Trestle Design

The trestle and deck of the marine terminal have been designed with sufficient height reduce theeffects of shading on habitat. Using a trestle-based jetty, rather than a rock fill-based causeway alsoresults in less disturbance to marine habitat, natural ocean current, and tide regimes. The trestledesign has been modified to allow safe passage of vessels, up to the size of a gill-netter(approximately 11 m clearance above high water), under the trestle at the commonly used navigablechannel close to Lelu Island. Marine Trestle Design

2.1.3.5 Overall Site Layout

Following public feedback on importance of visual effects and concerns with light and noise from thefacility as well as environment protection of intertidal zones, PNW LNG revised the master layoutphilosophy during pre-FEED to include a 30 m setback from the high water mark. Two additionaladvantages resulted from this: the area of surface disturbance has been reduced and many culturallymodified trees will be conserved.


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2.1.3.6 Siting of Flare

PNW LNG re-sited the main plant flare (for use in emergency situations for released gas) from thenortheast side of Lelu Island to the southeast side, following discussions with local stakeholders in

order to reduce effects from the plant flare on visual quality, ambient light, and noise.

2.1.3.7 Avoidance of Listed Plant Community

The facility layout has been designed to avoid a provincially red-listed estuarine plant community onLelu Island (see Section 10).

2.1.3.8 Design Carbon Footprint

The Project’s design standards require greenhouse gas emissions to be benchmarked with otherglobal LNG projects, measured in CO2e per tonne of LNG produced. Final engineering design aimsto meet or improve upon the target of 0.27 t CO2e/ t of LNG. Although not considered as aquantifiable benefit from the Project, making available LNG to end users who might otherwise use

more polluting forms of energy production will result in an incremental global reduction of GHGemissions.

Heat Recovery

In the LNG industry, heat from gas turbine exhaust is usually recovered for in-facility use to theextent possible. Even though this requires specialized heat recovery units to be inserted into gasturbine exhaust ducting and complex heat integration, it will improve overall facility efficiency. For theProject, heat from gas turbine exhaust will be recovered for heating, for example to supply heat toreboilers of distillation columns, and to supply heat to regenerate drier beds.

Aero-Derivative Gas Turbines

Until recently, few LNG projects were built using aero-derivative gas turbines. These turbines aremore efficient than the more commonly used industrial gas turbines. In FEED, PNW LNG hasdecided to use aero derivative gas turbines as the main compressor drivers, as well as for powergeneration, to achieve better environmental performance. The evolution of design for the Project issummarized below (see Table 2-1).

Table 2-1: Evolution of Drivers/Power Generation through Design Phases

Phase Compressor Driver Power Generation

DFS Industrial gas turbine Industrial gas turbine

Pre-FEED Industrial gas turbine Industrial gas turbine with heat recovery steam generator (HRSG)

FEED Aero-derivative gas turbine Aero-derivative gas turbine

Combustors

To further enhance emission performance, PNW LNG is evaluating the use of the latest combustortechnologies including dry low NOx (DLN) and dry low emission (DLE) systems.


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Adoption of LEED Principles for Building Design

PNW LNG has specified that buildings in the non-manufacturing area of the Project implement LEEDprinciples in their design as part of sustainable development efforts. The details of the

implementation are being determined in the on-going FEED.

Other Advanced Technologies

In LNG processes, there are several processing steps that require pressure reduction in bothgaseous and liquid form. This leads to cooling of the fluid, hence reducing energy required forliquefaction. Typically, pressure reduction is carried out by expansion of the fluid across speciallydesigned valves. The potential energy from pressure let down could be harnessed to generate asmall amount of electrical energy. PNW LNG is working with FEED contractors and suppliers toexplore the use of such expanders, which would lead to better environmental performance.

2.1.3.9 Flare Control System

Even though the Project is designed to a no-flare philosophy for routine operations, flare stacks arerequired for protecting people and the facility in the event of an emergency, to prevent pressure builtup in the system. The flares will have redundancy built in and will have pilot flames 24 hours a day.The pilot flame allows for the release volume to be immediately ignited during an emergency.

2.1.3.10 Bunker Fuel

The LNG carriers for the Project will be powered by both boil off gas (BOG) from the LNGtransported and bunker fuel during voyages. During consultation, the risk of spills from bunker fuelwas raised as an issue. Following this input, PNW LNG made a design decision to remove thebunker refueling facility at Lelu Island from the project design. Using LNG carrier’s BOG as fuelallows for this design change, which eliminates risks associated with bunker fuel spill during storage,transfer, and refuelling; it also reduces emissions compared with bunker fuel.

2.1.3.11 Propane Use and Storage

The requirement for propane injection into the LNG will vary depending on the final market usage.The facility will not undertake propane injection; this will occur, if required, at LNG carrierdestinations. This removes the need for two initially-planned 72,000 m3 propane storage tanks, apropane import berth, propane unloading arms, pressurized piping and associated injection piping.Elimination of this infrastructure also reduces the quantity of hazardous materials stored on site andreduces the complexity and safety risks associated with unloading of propane from marine vessels.

2.1.3.12 Water and Wastewater

To reduce discharge to the ocean, the majority of project wastewater will be treated and disposed of

through the District of Port Edward municipal wastewater system. All wastewater disposed through thePort Edward system will be pre-treated on-site to meet Port Edward standards. If capacity concernswith the Port Edward system arise, on-site treatment systems will be upgraded to meet demand andPNW LNG would apply for the relevant waste discharge approvals. The only ocean discharges will befrom stormwater runoff and sea water used for hydrotesting during commissioning. To avoid effects onsurface water and groundwater flows, all potable water for the facility will be sourced from the District ofPort Edward municipal water supply. During consultation, concerns were raised about water quality;


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use of the District of Port Edward infrastructure will reduce the potential effects from the Project onwater quality. A sea water treatment plant would be the only other potential water supply for theProject. The use of Port Edward infrastructure avoids the need for brine disposal that would berequired if a sea water treatment plant was used to supply water to the Project.

2.1.3.13 Noise Dampeners

To reduce noise emissions from the Project, design approaches and dampening systems will beimplemented. Where possible, extremely noisy equipment will be segregated to avoid addingtogether large acoustic emissions (superposition effects). Dampening systems may include:

Acoustic enclosures or acoustic blankets for refrigerant compressors, BOG compressorexpander-generator package and other main pumps

Noise hoods for compressor gearboxes

Acoustic insulation (4-inch-thick class D) for all suction, discharge and recycle piping for thecompressors, expander-generator package, and others main pumps

Silencers for all fans, blowers and suction inlets and outlets.

A noise barrier (approximately 6 m high) may also be constructed along the northwestern andnortheastern edges of the LNG train area of the facility.

2.2 Project Components

Industry standard is to divide an LNG plant into a “manufacturing area” and “non-manufacturingarea”. The manufacturing area can further be subdivided into several areas: LNG trains, utilities, andoffsite. Each of these areas is further divided into units, which are made up of major equipment (e.g.,pressure vessels, pumps, piping, heat exchanger, compressors, turbines). The major equipment issupported by electrical, instrumentation and control systems. The non-manufacturing area includes

workshops, offices, clinic and other supporting infrastructure.During construction, there are additional components described as temporary construction facilities(TCF), which are facilities that support delivery, storage and marshaling of materials duringconstruction. Construction housing is another main TCF. These facilities are typically removed afterconstruction is complete.

The Project will be developed in two distinct phases, with the key components tabulated in Table 2-2.

Table 2-2: Key Components of Project Phases

Components Phase 1 Phase 2

LNG Trains Two trains One additional train

LNG Storage and

Loading Two 180,000 m3 storage tanks Trestle with two berths

One additional 180,000 m3 storagetank

Utilities and Offsite Developed to cater two trains Expanded to cater for additional train

Non-ManufacturingFacilities

Materials offloading facility (MOF) Bridge and roads

MOF may be refurbished dependingon delay between Phase 1 andPhase 2

TemporaryConstructionFacilities

Developed to support constructionand commissioning of two trains

Some to be developed and somemay be refurbished from Phase 1,depending on time gap


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Project layout and key components are shown in Figure 1-4, and described in the following sections.The project components cover approximately 160 ha on Lelu Island and approximately 0.3 ha for theroad and bridge connect to Skeena Drive on the mainland. Marine components (terminal, MOF,pioneer dock, dredging, bridge crossing associated works) cover approximately 100 ha.

The project components described below are based upon the on-going FEED program, to the extentpossible without breaching confidentiality obligation between PNW LNG and process licensors. Inthe course of the program, it is expected that further refinement of the project components will takeplace. The final design may differ slightly in configurations and equipment sizing.

2.2.1 LNG Trains

PNW LNG intends to source natural gas produced in the North Montney area (or other availablesources) which has been pre-treated in gas plants in northeast BC. Gas will be transported to LeluIsland by the Prince Rupert Gas Transmission Project pipeline. The limit of the Project beginsdownstream of the gas metering station (GMS). The GMS measures the amount of natural gas

transferred by pipeline to the plant and defines custody transfer of natural gas from the upstreamseller to PNW LNG. The GMS and upstream pipeline is the responsibility of Prince Rupert GasTransmission, and is subject to a separate regulatory process.

Natural gas is processed in the LNG trains, stored in cryogenic storage tanks and then loaded ontoLNG vessels at the berth. This section describes the main process units of an LNG train.

2.2.1.1 Feed Gas Receiving Unit

PGRT will develop the GMS and other associated gas receiving facilities. Typical componentsinclude the GMS, pig receiver and filters. The feed gas receiving unit will then connect to PNWLNG’s systems, starting with the pressure let-down unit described below.

2.2.1.2 Pressure Let Down Unit

To ensure consistent pressure entering the LNG train, a pressure let down station regulatespotentially fluctuating pipeline pressure.

2.2.1.3 Gas Treatment Unit

Even though natural gas will have been pre-treated upstream, small quantities of carbon dioxide andother contaminants in the natural gas will arrive at the facility. These components must be removedfor safety of the process and so that the composition of the final LNG product meets end-usespecifications.

Contaminants are removed by a water-based solvent of activated methyl diethanolamine in the gas-

treating unit. PNW LNG has entered into license agreement with BASF SE for the supply of theOASE® purple technology for the acid gas removal unit. A typical gas-treating unit consists of

Gas adsorber tower (natural gas comes into contact with solvent to strip the contaminants)

Solvent regenerator tower and the associated reboilers and condensers

Lean solvent booster pumps, cooler, mechanical filter, carbon filter, and polishing filter

Lean/rich solvent heat exchangers


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Wash water pump and make-up pump

Rich solvent flash drum

Thermal oxidizer

Anti-foam injection package

Solvent storage tank, transfer pump, drain sump, sump hydrocarbon pump, and sump pump.

Contaminants stripped from the natural gas are sent to the thermal oxidizer for conversion to non-toxic forms. Solvent is recirculated in the unit and regenerated in the regeneration column using heatrecovered from gas turbine exhaust waste heat. This reduces waste solvent production.

2.2.1.4 Gas Dehydration Unit

Treated natural gas exiting from the gas treatment unit is saturated with water. In order to preventfreezing in the cryogenic section of the LNG train, the natural gas goes through a dehydration unit.This unit consists of pressure vessels filled with desiccants (also known as a molecular sieve) made

of ceramic materials, which absorb water. These materials are regenerated in automated cycles andtypically have operating lifespan of five years before being replaced.

In order to lower emission to atmosphere, heat for regenerating the molecular sieve is supplied bythe waste-heat recovery unit.

2.2.1.5 Mercury Removal Unit

Trace levels of mercury can be present in feed gas. For safety of end users, plant operations andmaintenance crews—as well as protecting aluminum-based heat exchangers—a mercury removalunit removes trace mercury. Two techniques are commonly used: sulfur impregnated activatedcarbon or the metal hydride based catalysts. Any mercury that is present reacts with these catalystsand is retained in the catalyst particles. The catalyst is contained in large pressure vessels.

These catalysts cannot be regenerated and have to be disposed as hazardous waste. PNW LNG isidentifying suppliers to collect the spent catalyst as part of lifecycle management. These catalystsalso have typical lifespan of five years.

2.2.1.6 Fractionation Unit

Recovery of heavier fractions in feed gas for use as refrigerant components—especially if richer feedgas is supplied to the Project—is being investigated by the FEED teams. Recovery of these fractionswill reduce reliance on imported refrigerants and potentially make the Project self-sufficient. Ifrecovery is used, the fractionation unit typically consists of the following components:

De-methanizer column with associated reboilers and air cooled condensers

De-ethanizer column with associated reboilers and air cooled condensers De-propanizer column with associated reboilers and air cooled condensers

De-butanizer column with associated reboilers and air cooled condensers

Propane storage bullet

Butane storage bullet.


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2.2.1.7 Liquefaction Unit

Treated natural gas is sent to the liquefaction unit where it is gradually cooled by refrigeration cyclesuntil it changes from a gas to a liquid (at approximately minus 160oC). To reduce effects on marine

environment, the Project will use air cooling instead of sea water cooling.The facility will contain up to three identical 6.4 MTPA liquefaction trains (two to be constructed inPhase 1 with provision for a third train in Phase 2). Liquefaction will use either the propane pre-cooled mixed refrigerant (C3MR) process by Air Product and Chemical Inc. (ACPI), or theConocoPhillips Optimized Cascade® process. Generic descriptions of the processes are presentedin Section 2.4.1.

Each train in the C3MR process consists of:

Propane pre-cooler heat exchanger

Propane compressors and aero-derivative gas turbine drivers

Air cooled heat exchangers

Mixed refrigerant compressors and aero-derivative gas turbine drivers

Spiral-wound main cryogenic heat exchanger (MCHE)

LNG liquid expander (if used)

LNG end flash vessel, compressor, LNG rundown pump (if used).

Each train in the Optimized Cascade process consists of:

Propane or propylene compressors and aero-derivative gas turbine drivers

Ethylene compressors and aero-derivative gas turbine drivers

Methane compressors and aero-derivative gas turbine drivers

Three heat exchangers (cold boxes) to liquefy natural gas by stages Propane or propylene circuit air plate-fin heat exchanger (PFHE) and surge tank

Ethylene circuit air PFHE and surge tank

Methane circuit air PFHE and surge tank.

In both processes, waste heat from the gas turbine exhaust will be recovered and used in other units(e.g., fractionation unit reboilers, molecular sieve regeneration, and solvent regeneration). Thisenhances energy efficiency and reduces atmospheric emissions.

2.2.2 LNG Storage and Loading

Up to three 180,000 m

3

full-containment, double wall LNG storage tanks will be constructed for thefacility (two in Phase 1, with provision for a third in Phase 2). The tanks will consist of 9% nickel steel(which has increased fracture toughness for cryogenic uses) inner tanks, with outer tanks consistingof a post-tensioned concrete wall connected rigidly to the outer tank concrete slab, with a roofconstructed of reinforced concrete. Both the inner and outer tanks are liquid- and vapor-tight innormal operations. The annular gap between the inner and outer tanks is filled with insulation(see Figure 2-1).


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Figure 2-1: Full-Containment, Double Wall LNG Storage Tank

SOURCE:

GIIGNL 2009.

The tanks will include instrumentation and systems for level, pressure and temperature recording,leak/gas detection and cool down control, valves for pressure and vacuum protection, and a firedetection (flame and heat) and protection control system using dry chemical for relief valves.

Due to heat in-leak to tanks and from running pumps (especially during ship loading), some LNG willvaporize. Instead of flaring, any boil off gas and vapor generated will be consumed in plant as fuel,

used as refrigerant or re-injected into process stream to be re-processed into LNG.

2.2.2.1 Marine Infrastructure

The terminal will consist of a jetty supported by a trestle (see Figure 2-2) and including a field controlroom, LNG carrier berths, loading arms, and insulated cryogenic piping. Berths at the end of thetrestle will be capable of berthing 217,000 m3 LNG carriers (Q-Flex) up to 315 m in length.

The trestle will extend approximately 2.4 km offshore from Lelu Island, along the Flora Bank (seeFigure 1-3 and Figure 2-7). This location was chosen to reduce the environmental footprint.Breakwaters may be constructed near the marine terminal. Construction of the marine terminal,access channels and a turning basing require dredging an estimated 7 million m3 of marinesubstrate. This dredging covers an area of 84.6 ha, with depths down to 15.6 m and slope angles of

6 horizontal to 1 vertical (6H:1V). Refer to Section 2.4.6 for additional discussion on siting the trestle.For the bathymetry of these areas, see Figure 2-7. Anchorages and navigation aids associated withthis marine infrastructure are discussed in Section 15.


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Figure 2-2: Partial Trestle Profile

2.2.2.2 Loading and Vapor Return Arms

LNG from storage tanks is pumped to the loading berth then loaded into the ship by marine loadingarms. There will be two dedicated liquid arms, one hybrid arm and one vapor return arm. The armsare connected to LNG carrier manifolds. These arms are designed to automatically disengage insevere weather or in emergency to allow LNG carriers to depart.

2.2.3 Utilities and Offsite

To support the operations of the LNG trains, utilities such as power, nitrogen production, and

instrument air must be made available.

2.2.3.1 Flare System

For managing upset operating conditions and emergencies, there will be two flares for reliable andsafe disposal of hydrocarbon streams. The main flare is of a derrick supported multi-riser elevatedflare, consisting of warm, cold and spare flares. The warm flare handles warm/wet hydrocarbonreleases from the front end of the LNG trains. The cold flare handles cold/dry releases from theliquefaction and refrigeration areas. The spare flare is designed as a cold flare to be used as atemporary replacement for either the cold or warms flares during maintenance. The final height willbe determined in FEED by flare radiation modelling, based on maximum heat flux. Modelling of airand noise emissions for this assessment assume a height of 100 m.

The main flare is located at the southeast end of Lelu Island (see Figure 1-4). A low pressure (LP)flare is located on the northwest side of the island. This location reduces the length of the flare linefrom the BOG compression system and LNG storage tanks. The LP flare is a 60 m self-supportingstack. The LP flare combusts cold vapour released from the LNG storage areas during upsetconditions or an emergency event.

Both the main plant flare and the low pressure flare will have ignited pilot lights at all times forreadiness to address emergency situations.

2.2.3.2 Electrical Power Supply

Most energy for operating the facility will be supplied by the gas turbine drivers in the liquefactionunit. Details of driver alternatives and electrical power supply alternatives are provided in Sections

2.4.2 and 2.4.3. The electrical power supply for operations of the large process pumps, cooling fans,lighting and others will be self-generated so that the reliability and timeliness of supply availability ismaintained. Because a failure power supply would interrupt operations of the facility, PNW LNGadopts a power generation sparing philosophy of N+2 to prevent power failure (i.e., number ofrequired supply units (N) plus two spares).


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The electrical power requirement is up to 500 MW for three trains, at full build-out (Phase 2). TheFEED teams are developing designs that are consistent with reducing GHG emissions, including theuse of more efficient aero-derivative gas turbines.

The power plant will be designed to accept connection to an external utility power supply, in theevent that renewable energy production capacity becomes available in the future.

2.2.3.3 Other Bulk Storage

Other bulk materials stored at the facility will include refrigerant and heat transfer fluid. Refrigerantsare stored in a refrigerant unit, housing pressurized cryogenic storage tanks for ethylene, ethane,propane, propylene and butane, depending on which liquefaction technology is finally selected.

Heat transfer fluid (also known as hot oil) is used for process heating. Depending on design, a cone-roof tank may be included. The hot oil storage tank is connected to an expansion drum to provide abuffer for expansion in the system volume and removal of gases mixed with the hot oil.

2.2.3.4 Water Supply Infrastructure

PNW LNG intends to secure potable water supplies for the Project from the District of Port Edwardmunicipal supply. The District’s water treatment plant has capacity of approximately 2,400 m3/day.Total projected water supply requirements for the District—including demand from the Projectof 875 m3/day during construction and 50 m3/day during operations—are expected to reach3,500 m3/day by 2033. A 150 mm diameter pipeline will be constructed, connecting the existingnetwork to Lelu Island. At the bridge, a submerged crossing will be used until the bridge isconstructed. Once bridge construction is completed, the submerged crossing will remain in place asa planned redundancy.

To maintain a water supply from the municipal system, PNW LNG will work with the District of PortEdward to upgrade elements of the water supply infrastructure. These upgrades are not part of the

Project, but will include upgrades to components of the water treatment plant to increase capacity to3,600 m3/day; construction of a 1,600 m3 balancing reservoir either at an expanded treatment plantor across from Lelu Island; and upgrades to sections of the District’s distribution network to 200 mmdiameter pipe.

2.2.3.5 Wastewater Treatment Systems

PNW LNG intends to process sewage output from the Project through the District of Port Edwardmunicipal wastewater treatment system. The District’s wastewater treatment plant has capacity fortreating approximately 2,400 m3/day. Total projected wastewaters flows for the District—includingdemand from the Project of 875 m3/day during construction and 50 m3/day during operations—areexpected to reach 2,035 m3/day in 2017. Existing wastewater treatment headworks have sufficient

capacity to handle these flows.Other upgrades to the plant will be required to meet long-term demand. PNW LNG will work with theDistrict to upgrade elements of the water treatment system. These upgrades are not part of theProject, but will include converting an existing digester into a third oxidation ditch, constructing a newaerobic digester, and constructing a new clarifier.


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To connect to the municipal wastewater collection system, PNW LNG will construct a new pumpingstation and 150 mm diameter forced mains to connect to the District’s gravity sewer. As with theconnection of the municipal water supply, the connection at the bridge will be a submerged crossinguntil the bridge is constructed. Once bridge construction is completed, the submerged crossing willremain in place as a planned redundancy. Wastewater during plant operations will be pre-treated inthe plant to meet the specification of an upgraded Port Edward wastewater treatment plant.

Sea water used for hydrotesting of various storage tanks and facility utilities during construction(approximately 193,107 m3) will be discharged to the ocean through an outfall at the end of the marineterminal (at least 30 m from any sensitive environments i.e., eelgrass). The testing water will bedechlorinated with sodium bisulfite to remove sodium hypochlorite (used to mitigate biological growthduring testing) before discharge through the outfall. The discharge will be authorized by the PRPA incooperation with the BC Ministry of Environment (BC MOE) as part of the outfall permitting process.

2.2.3.6 Stormwater Management Infrastructure

Stormwater runoff from plant areas subject to oil contamination will be curbed or diked and collectedby a segregated, underground oily-water sewer system. This system will drain to a CPI oil-waterseparator system for oil removal. Runoff water will then be discharged at the marine terminal outfall.Runoff from other, non-curbed areas of the facility will be collected by perimeter ditches draining to afirst flush basin. The basin will collect the first 25 mm of runoff, with the excess diverting to the cleanrunoff system. Clean runoff water will be collected by surface ditches for direct discharge to theocean through shoreline outfalls. Drainage and erosion controls will be implemented to retain thebaseline hydrological regime and protect ecological communities of management concern locatedadjacent to the PDA. Locations of the shoreline outfalls have not been finalized, but will be at least30 m from any sensitive environments i.e., eelgrass.

2.2.3.7 Fire Control Infrastructure

The fire control infrastructure for the Project will consist of four elevated firewater monitor towers atthe LNG carrier berths; two firewater storage tanks; heated shelter enclosed fire water pumps; and acombined fire station and security building. Fire water mains will supply fire water to the entire facilityand pressure will be maintained in the system at all times for readiness. In addition, backup seawater pumps will be installed to supply sea water for firefighting, if required.

The Project will have a fire station with a fire truck and foam tender, as well as specialized fire controlequipment.

2.2.3.8 Nitrogen Generation System

The nitrogen generation system will produce gaseous nitrogen for normal consumption and liquidnitrogen for storage. Nitrogen will be used for purging flare headers, in the laboratory and workshop,and for other minor purposes. The system will consist of two cryogenic nitrogen generators andvaporizer packages rated at approximately 65 kW each and a liquid nitrogen vertical storage vessel.

2.2.3.9 Compressed Air System

A compressed air system will supply air for instrumentation (instrument air), input to the nitrogensystem, and for pneumatic tools and other utility needs (plant air). The air system will consist of:

Air compressor package


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Emergency air compressor package

Instrument air dryer

Wet air receiver

Instrument air receiver

Air distribution plumbing.

2.2.4 Non-Manufacturing Facilities

2.2.4.1 Materials Offloading Facility

The materials offloading facility (MOF) will be located in a small cove on the north side of Lelu Island,oriented parallel to Porpoise Channel (see Figure 1-4). The MOF layout will be designed to takeadvantage of the local terrain of the cove to reduce blasting requirements. Construction of the MOFand the associated turning basin requires dredging an estimated 690,000 m3 of marine substrate.

This dredging covers an area of 5.4 ha, to a depth of 10 m, with slope angles of 2 horizontal to 1vertical (2H:1V). Additional overdepth dredging will be to 12.5 m, with box cut (vertical) sides. Detailsof the sediment and substrate in the dredging area are provided in the Marine Sediment TechnicalData Report (Appendix L) and summarized in the Marine Resources Assessment (Section 13).

Construction of the MOF will use drilled piles and will occur year round until complete.

2.2.4.2 Bridge and Roads

The facility on Lelu Island will be accessed from the mainland via a multi-span bridge connecting tothe northeastern edge of the island to Skeena Drive (Highway 16). The bridge will also pass over theCN rail line at this location. Construction of the bridge will also require upgrading Skeena Drive and aprivate road at the eastern abutment of the bridge. Upgraded wastewater and potable water mains

will be installed in the road right-of-way (ROW) and along the bridge.

Service roads will also be constructed throughout the facility for general facility vehicular traffic,maintenance, operations, and firefighting access. The road system also provides segregationbetween adjoining process units to reduce the risk and spread of localized fires. Service roads willnot have dead ends, to avoid restrictions to traffic and personnel during emergencies.

2.2.4.3 Administration and Maintenance Buildings

Administration buildings are currently planned to be located on a peninsula on the northeast coast ofLelu Island. These include an administration building, canteen, clinic, weather station,communications tower, parking areas, and a security post. The maintenance building will be located

just inland of the peninsula, on the northeast coast and will comprise a warehouse, workshop, andlaboratory. The combined fire station and security building will also be part of this complex, and anadditional security post will be located at the entrance to this area. Final locations and designs of thebuildings will be decided in FEED. PNW LNG has required the buildings to be designed inaccordance to appropriate LEED Guidelines.


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2.2.4.4 Site Fencing

The facilities on Lelu Island will be surrounded by security fencing for access control. They willgenerally have a minimum height of 2 m, post spacing of 3 m, and include 3-string barb-wire top

inclined at 45º (70 cm wide).

2.2.4.5 Site Lighting

Lighting fixtures for the Project will use luminaires that reduce wasted light and stray light causinglight pollution. The Canada Green Building Council LEED (LEED 2004) and InternationalCommission on Illumination (CIE 2003) guidelines on lighting design will be considered for finallighting design.

2.2.4.6 Fisheries and Wetland Compensation

Habitat compensation will be developed for the Project as outlined in the Conceptual Fish HabitatOffsetting Strategy (Appendix K) and Wetland Habitat Compensation Strategy (Appendix F).

2.2.5 Temporary Construction Facilities

2.2.5.1 Pioneer Dock

A temporary pioneer dock for initial off-loading of construction equipment (prior to construction of theMOF) will be developed north of the MOF. The dock will consist of floating pontoons secured withpiles, a rock/gravel ramps to land, and a gangway; it will be decommissioned once equipment cantransfer through the MOF and bridge.

2.2.5.2 Temporary Construction Camp

A temporary work camp that will accommodate between 3,500 and 4,500 people at peakconstruction will be constructed, operated and decommissioned. The camp will be constructed in

accordance with the Industrial Camps Regulations under the BC Public Health Act . The camp will belocated on the southeast end of Lelu Island, in the area of the main flare stack. When the flare stackis constructed, the camp size will be reduced to remain outside of the flare safety zone.

The camp will have sewage treatment requirements of approximately 875 m3/day; this would betreated by an expanded facility in Port Edward. The camp will also have potable water requirementsof about 875 m3/day. A proposal has been issued to the District of Port Edward to tie into andupgrade their water supply system to supply camp and other construction water supply requirements.

2.3 Project Activities

The anticipated schedule for the Project is indicated in Table 2-3. Timelines for cessation ofoperation are uncertain, but likely to exceed 30 years.


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Project No. 1231-10537 2-17

Table 2-3: Project Schedule

Project ActivitiesTimeline

Start Finish

Bridge and Access Road Construction Q1 2015 Q2 2016

Site Clearing and Preparation Q1 2015 Q2 2016

Construction Camp Q2 2015 Q3 2016

Construction of Materials Off-loading Facility (including dredging) Q1 2015 Q4 2016

Construction of Jetty-Trestle, Berths and Marine Terminal (includingdredging)

Q3 2015 Q3 2018

LNG Tank Construction Q1 2016 Q3 2018

LNG Train 1 Construction and Commissioning (Phase 1) Q3 2016 Q3 2018

LNG Train 2 Construction and Commissioning (Phase 1) Q4 2016 Q4 2018

Operations (Phase 1) Q1 2019 2048+

LNG Train 3 Construction and Commissioning (Phase 2)a TBD TBD

Decommissioning (or facility refurbish/re-commissioning) 2048+ –

NOTE:a Timing of construction of Phase 2 will depend on market conditions.

2.3.1 Construction

Construction of the facilities will commence upon receipt of regulatory and permitting approvals.

Construction works and activities will include:

Site preparation (land based)

Onshore construction

Vehicle traffic

Dredging

Marine construction

Waste management and disposal

Disposal at sea

Operational testing and commissioning

Site clean-up and reclamation.

2.3.1.1 Site Preparation (Land Based)

Approximately 87% (160 ha) of the land—predominantly bog wetland and forest—on Lelu Island will

be cleared and graded. The site is planned to be leveled at an elevation of 25 m, requiring cut and fill

of approximately 11 million m3. Vegetation removal will be avoided within 30 m of the high water

mark (HWM) to maintain the ecological function of the riparian area and the archaeological value of

the culturally modified trees (CMTs) in this area of Lelu Island.


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Prior to site preparation, the extent of the project development area, MOF landing site, trestle landingsite, and bridge abutments will be surveyed and flagged.

The surface materials on Lelu Island are composed primarily of peat (muskeg) and organic soils,

generally underlain by overburden (sand, gravels, and silts) overlying bedrock. Graders, bulldozers,backhoes and other earth moving equipment will be used to strip the surface materials andoverburden. Peat removed during construction will be stored on Lelu Island.

Following clearing and grading, site drainage will be incorporated into the site development. A stable,flat and safe work surface will be created with appropriate sediment control measures. Exposedbedrock will be ripped mechanically or blasted. In areas where the existing elevation of the bedrockis below the final site grade, engineered fill will be used to bring the surface up to the finished grade.Undeveloped areas (not including conserved riparian buffers) will be contoured, and erosion controlmeasures will be implemented.

2.3.1.2 Onshore Construction

Bridge and Access Road

To facilitate access for construction on Lelu Island, construction of the bridge across Lelu Slough andthe access road connecting Skeena Drive to the bridge will be the first construction activity. Thebridge will be a multi-span continuous bridge on a raised vertical alignment, which will include anoverhead CN Railway crossing. It will have a deck-girder superstructure with a full-depth precastconcrete panel deck supported on continuous plate steel I-girders. Construction will require areinforced 1H:1V fore-slope under the mainland abutment.

The access road joining the bridge to Skeena Drive will include a southbound right-turn lane (taperand radius only). The access road will be constructed to a 60 km/h design speed, according toprovincial and federal guidelines.

Construction Camp and Utilities

The construction camp will initially be a 500-bed temporary camp expanding to accommodate up to4,500 workers during peak construction. Upgrades to the District of Port Edward water andwastewater systems and connections to those systems from Lelu Island will provide these facilities tothe camp (see Section 2.2.5.1).

Heavy-Haul Road

A heavy-haul road will be constructed on Lelu Island to facilitate construction traffic and transport ofheavy equipment and facility modules from the MOF to facility sites (see Figure 1-4). The haul road

is designed to align with the final facility road network where possible and will be replaced by theseroads late in the construction phase.

LNG Production Facilities

Construction of the LNG production facilities includes excavating building sites, pouring foundations,constructing facility buildings and drainage systems, and installation of the infrastructure. Foundationrequirements are expected to be reinforced concrete slab-on-grade; however, this will be clarifiedfollowing a detailed geotechnical investigation. The facility will be built as a combination of stick-built,


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Project No. 1231-10537 2-19

constructed in-place (e.g., LNG storage tanks), and use of modular prefabricated units. Due to the

volume of concrete needed for the foundations and LNG tanks, a concrete batch facility will be

established onsite.

The timing of construction of Phase 2 of the Project (LNG train 3 plus one storage tank) will dependon market conditions. Phase 2 construction would occur over approximately 40 months and require a

workforce of, on average, 50 people per month. Up to several hundred people could be needed

during peak construction.

Power Generation

Power generation for construction, including for the construction camp, will be supplied by onsite

diesel generators or, if available in a timely manner, electricity provided by BC Hydro. A system

impact study is underway to determine power availability and timing.

2.3.1.3 Vehicle Traff ic

Vehicle use for personnel and equipment transport will use the bridge connecting the mainland toLelu Island, as well as roads on island and feeder roads leading to the island.

2.3.1.4 Dredging

The safe maneuvering and berthing of construction barges and LNG carriers will require dredging of

the embayment area off Porpoise Channel, at the MOF berth face, and at the marine terminal berths

and approach to provide the necessary under-keel clearance. Approximately 690,000 m3 of material

over an area of approximately 5.4 ha will be dredged for the MOF and approximately 7 million m3 of

material over an area of approximately 84.6 ha for the marine terminal. Maintenance dredging at the

marine terminal is anticipated every two to five years. Maintenance dredging at the marine terminal is

anticipated every two to five years. In the event seabed alteration encounters bedrock, underwater

blasting may be required in the MOF area.

2.3.1.5 Marine Construction

Pioneer Dock

The pioneer dock will be the first infrastructure to be constructed. Piles to support pontoons will be

pre-drilled and grouted into the rock substrate. A temporary road and laydown area will be cleared

from the dock ramp and gangway.

Bridge

The bridge connecting Lelu Island to the mainland will rest on five steel-pipe piers with concrete

abutments. These abutments and piers will be installed in Lelu Slough progressively from the bridgework.

Materials Off-Loading Facilit y

The MOF will be constructed to berth roll-on/roll-off (RO/RO), heavy lift vessels and barges to

transport material for facility construction. The “L” shaped MOF will be constructed on pilings driven

through sediment and anchored into the underlying bedrock. During construction, the MOF will be

used for berthing of RO/RO and heavy lift vessels.


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Marine Terminal

The marine terminal will incorporate pipe-pile supported trestle and berth structures. Piles will bedriven through the sediment and anchored into the underlying bedrock. A vibratory hammer will be

used to drive the piles to the bedrock where geotechnical conditions permit. Both the trestle andberths will consist of cast-in-place concrete caps, pre-stressed precast girders, and cast-in-placedeck slabs. The deck slabs will be installed using marine equipment. Breakwaters near the marineterminal may also be constructed.

2.3.1.6 Waste Management and Disposal

Clearing Materials

CMTs that require removal will be offered to local First Nations for traditional use. Following this, anymerchantable timber on Lelu Island will be harvested by local enterprises and removed from the site,where practical. Other non-merchantable trees and vegetation will be chipped. Large stumps and

rocks will be removed from the cleared site. Organics (i.e., peat) will be piled and stored on LeluIsland for draining.

Overburden from the terminal site will be temporarily stockpiled onsite and transported to anapproved disposal area where necessary. Sand and gravel will be salvaged and incorporated intothe cut-fill balance where available.

Stormwater

Stormwater run-off will be managed as described in Section 2.2.3.6.

Solid, Liquid and Hazardous Wastes

Solid wastes from construction areas will be removed, transported, and recycled or disposed at

approved disposal sites in compliance with any regulatory requirements. Sewage effluent will betreated via connection to the District of Port Edward wastewater treatment facility. Hazardous wasteswill be disposed offsite at an approved disposal facility.

2.3.1.7 Disposal at Sea

Dredged material will be used as fill on Lelu Island, where practical. Remaining dredged material willbe disposed at an EC approved ocean disposal site (e.g., Brown Passage). Approval for disposalwould be requested from EC under the Canadian Environmental Protection Act . Alternate oceandisposal sites may be considered if they are suitable and if they have the support of the community,First Nations, and the regulatory authorities.

2.3.1.8 Operational Testing and Commissioning

Liquid effluent from commissioning, including sea water used for facility hydrotesting, will be treatedonsite and disposed at the marine terminal outfall.


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2.3.1.9 Site Clean Up and Reclamation

At the end of main construction activities—as well as on an on-going basis—post-constructioncleanup will occur. When appropriate, cleanup will be followed by re-vegetation of areas cleared for

construction purposes that are not required for the final facility.

2.3.2 Operations

At full build-out (Phase 2), the Project will have capacity to produce 19.2 MTPA of LNG, using9.1 x 107 m3 per day of feed gas. The Project will be designed to allow for continuous operation, 24hours a day and 365 days a year. Activities assessed during the operations phase of the Projectinclude:

Operation of LNG facility and supporting infrastructure on Lelu Island

Marine terminal use

Shipping (between the terminal and Triple Island)

Waste management and disposal

Fish habitat offsetting

Wetland habitat compensation.

2.3.2.1 LNG Facility and Supporting Infrastructure on Lelu Island

Normal operation activities are those associated with the Project being in stable, continuousproduction. These activities include start-up, shutdown, slowdown and maintenance activities.

Personnel will staff the facility 24 hours per day and 365 days, in 12-hour shift cycles. Shiftoperations teams will consist of dedicated personnel for individual LNG process trains, utilities, theterminal and laboratory. All operations activities for PNW LNG will be directed and controlled from

the main control room (MCR). All information necessary for running the facilities will be available inthe MCR. Field operators shall be available for manual interventions of the plant operations includingstart-up, normal operation, shutdown, and upset. Operators shall be capable of performing minormaintenance activities such filter replacement, equipment cleaning, control valve stroke check, lubeoil top up, greasing, gasket replacement, and mechanical fittings.

Routine maintenance activities include preventive and breakdown maintenance. More complexmaintenance activities are also carried out in regular intervals and often require shutting down anLNG production train (partially or entirely); for example, inspection and maintenance of gas turbines.PNW LNG will have in-house capabilities to carry out all routine maintenance activities and may useexternal resources for major maintenance activities.

LNG Production and Storage

The LNG facility will produce 12.8 MTPA of LNG using two production trains during Phase 1 ofoperations. During Phase 2, a third train would increase production capacity to 19.2 MTPA. ThreeLNG storage tanks at the facility will store up to 540,000 m3 of LNG. LNG liquefaction will take placeusing either the propane pre-cooled mixed refrigerant (C3MR) process, or the ConocoPhillipsOptimized Cascade® process. These processes are described in Section 2.2.1.7. The Project isdesigned to be fully air cooled to reduce potential effects on the aquatic environment.


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Natural gas-fired turbines will provide up to 1,100 MW of combined mechanical and electrical powerfor the facility (including spare units). Turbines will operate continually to drive mechanical systemsfor the production process and provide electrical power for facility equipment. Depending on finaldesign, the facility will store quantities of hot oil, ethylene, propylene, ethane, propane, and dieselfuel. These materials will be used in the LNG production process, or as fuel.

Facility Inspections and Maintenance

Routine inspections, testing and maintenance of all systems will be completed on an ongoing basis for:

Maintenance of equipment for safe and reliable operation

Inspection of equipment and facilities to maintain mechanical integrity and performance

Road and site maintenance

Inspection and maintenance of safety, civil structures, and environmental monitoringdevices.

2.3.2.2 Marine Terminal Use

Stored LNG will be loaded for export onto LNG carriers at the berths. During Phase 1 of operation,up to one LNG carrier will be loaded every two days, increasing to up to one LNG carrier per dayafter Phase 2 is constructed.

Up to two LNG carriers will be moored at the LNG berths. Each berth will have four breastingdolphins and six mooring dolphins joined by walkways to the main loading platform.

LNG loading arms will also have a return vapour line for BOG, which will be returned to the BOGcompressor.


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Project No. 1231-10537 2-23

Figure 2-3: LNG Carrier Berthed at a Marine Terminal (Malaysia LNG)


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2.3.2.3 Shipping

For the first phase of the Project (12.8 MPTA) it is estimated that there will be one LNG carrier everytwo days calling on the port. At full build out (19.2 MPTA), this frequency will increase to

approximately one LNG carrier call per day and 350 LNG carrier calls per year. There will be avariety of LNG carrier sizes that can use the marine terminal. The largest vessel that the terminal isdesigned to accommodate is the Q-Flex LNG carrier. This LNG carrier is up to 315 m in length and50 m wide with a 12 m draught. The Q-Flex has capacity to ship up to 217,000 m3 of LNG; its grossregistered tonnage is 136,410 t with deadweight of 106,897 t.

The LNG carriers will use pre-established shipping routes into the Port of Prince Rupert incoordination with the Pacific Pilotage Authority and under the control of BC Coast Pilots. Deep seavessel traffic heading for Prince Rupert harbour currently approaches from the open waters north ofthe Haida Gwaii, through Dixon Entrance, north of Stephens Island, following the deep sea shippingroute into the PRPA (see Figure 2-8). Pilotage into the area past Dixon Entrance is compulsory for allvessels over 350 gross tonnes. The current pilot boarding station is located off Triple Island, at the

eastern end of Dixon Entrance, north Stephens Island and approximately 49 km from Lelu Island. Accordingly, all LNG carriers will be escorted to Lelu Island by the BC Coast pilots assisted by tugs.The size and number of tugs will comply with PRPA policies and procedures and meet requirementsdetermined from docking simulations.

The PRPA has established anchorage locations within PRPA harbour limits. It has also identifiedadditional anchorages available outside the harbor limits for potential use by LNG carriers; the use ofanchorages outside of harbour limits will be at the discretion of the vessel and the pilot. Mooring locationsnear Lelu Island can be found on the PRPA website (http://www.rupertport.com/operations/navigation).

The shipping of LNG will be conducted separately from the operation of the LNG facility and marineterminal. The party responsible for the care and control of the LNG once it leaves the terminal willvary depending on the contractual arrangements made between PNW LNG and its customers. In

cases of free-on-board delivery (FOB), PNW LNG will transfer the ownership of the LNG as it leavesthe terminal and the LNG carrier is loaded. The buyer will be responsible for providing a vessel,either its own or a third-party owned. Thus, with an FOB arrangement, the care and control of theLNG will transfer from PNW LNG to the buyer/shipper as the LNG carrier is loaded. Alternatively,with ex-ship delivery (DES) agreements, PNW LNG will be responsible for transport of the LNG andretain ownership of it until it is delivered to the customer’s discharge port. In both scenarios,PNW LNG or the buyer could make use of ships owned and operated by Malaysia InternationalShipping Corporation Berhad (MISC), which is a subsidiary of PETRONAS or it could contract athird-party LNG carrier. In all cases, companies other than PNW LNG will undertake shipping of theLNG. Depending on the contractual arrangements made between PNW LNG and its customers,either FOB or DES, the LNG may or may not be transported for the exclusive use of PNW LNG. Theviability of the Project is not dependent on a third-party LNG carrier service calling on the facility.

2.3.2.4 Waste Management and Disposal

Facility Emissions and Waste

Moving parts in process machinery and vehicle use associated with operations will result in noise.Facility lighting and flare operation will emit light. Air emissions would include nitrogen oxide (NOx),carbon monoxide (CO), sulfur dioxide (SO2), particulate matter (PM), volatile organic compounds


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Project No. 1231-10537 2-25

(VOC), and hazardous air pollutant (HAPs). The Project will also generate greenhouse gas (GHG)

emissions through LNG processing and power generation.

Emissions originate from each LNG train and the common support utility facilities. Air emissions

sources include combustion products from:

Gas turbines from each LNG train

Thermal oxidizers from each LNG train

Flares (non-routine use only)

Back-up generators (for critical components in case of an emergency)

Firewater pump drivers

Fugitive emissions

LNG carriers and tugs.

There will also be fugitive emissions from equipment (e.g., excavators, trucks) on the site and

periodic emissions that originate from the routine maintenance and readiness testing of backup andemergency equipment items (e.g., emergency diesel generators, pumps).

Stormwater

Stormwater run-off will be managed by the infrastructure described in Section 2.2.3.6.

Solid, Liquid and Hazardous Wastes

Solid wastes produced during operations will include domestic wastes, paper, cardboard waste, and

wood and metal scrap from the maintenance facility. These wastes will be removed, transported, and

recycled or disposed at approved disposal sites in compliance with regulatory requirements.

Liquid effluent from operations will be treated onsite. This includes contaminated stormwater or water

contaminated in the LNG processes, water discharge from steam or condensate blow-down, and

solvent or hydrocarbon contaminated wastewater and wash water, and surface runoff. Treated

effluents from the plant will be transported by pipeline to the Port Edward wastewater treatment facility

for treatment and disposal. Stormwater and LNG tank test sea water will be treated to remove any

contaminants and then discharged to the ocean through an outfall at the end of the marine terminal.

Hazardous wastes produced during operations are likely to include:

Solvents or hydrocarbons from contaminated wastewater and surface runoff

Trace mercury removed during the natural gas treatment process

Waste catalyst and adsorbents

Waste lubricating oils Spent solvents

Medical wastes

Biological sludge

Minor miscellaneous wastes, such as used cartridge filters, batteries.


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These wastes will be disposed of offsite at an approved disposal facility. Additional detail on wastemanagement is provided in the Waste Management Plan (see Section 24).

Vegetation Management

Physical and chemical management will be used to control vegetation in and around the facility,including areas on Lelu Island and around the road and bridge on the mainland. Application ofherbicides will be restricted near sensitive vegetative communities and vegetation removed will bedisposed at an approved disposal facility.

Shipping Waste

Canada is a signatory to the International Convention for the Prevention of Pollution from Ships (MARPOL). Therefore, emissions from the LNG carriers will comply with the regulations onemissions of sulfur oxide (SOx) and NOx in MARPOL Annex VI, applicable Canadian regulations, andthe applicable North American Emission Control Area regulations to which Canada has subscribed.

Under the Ballast Water Control and Management Regulations (SOR/2011-237), “all vessels areexpected to exchange or treat their ballast water prior to discharge in waters under Canadian jurisdiction”. Ballast water treatment and exchange must be in accordance with InternationalMaritime Organization (IMO) guidelines (TC 2012). Under the Vessel Pollution and DangerousChemicals Regulations (SOR/2012-69), Division 4, a “vessel must not discharge sewage or sewagesludge” in waters under Canadian jurisdiction without prior treatment, and under Division 9, “Theauthorized representative of a vessel must ensure that any release of greywater by or from thevessel into the water does not result in the deposit of solids in the water or leave a sheen on thewater”. Therefore, introduction of invasive species from bilge and ballast water is not considered inthis EIS/Application.

2.3.2.5 Fish Habitat Offsetting

Restoration, enhancement or creation of fish habitat will be developed as a component of theoffsetting plans; these programs will take place as early as possible in the construction andoperational phases.

2.3.2.6 Wetland Habitat Compensation

Restoration, enhancement or creation of wetland habitat will be developed as a component of thecompensation plans; these programs will take place as early as possible in the construction andoperational phases.

2.3.3 Decommissioning

If rejuvenation of the facility is not a viable option at the end of the life of the facility (estimated to bea minimum of 30 years), a decommissioning and final rehabilitation plan will be developed inconsultation with the PRPA, applicable regulatory authorities, and local First Nations.Decommissioning may include:

Dismantling facility and supporting infrastructure (major elements may remain in place)

Dismantling of marine terminal (major elements may remain in place)

Waste disposal


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Site clean-up and reclamation.

A monitoring program for assessing the effectiveness of rehabilitation and decontamination efforts atsite would be developed as part of decommissioning. On-going environment monitoring would be

undertaken for a period of time to confirm decontamination and rehabilitation efforts have beensuccessful and that there is no further contamination resulting from previous activity.

PETRONAS (as PNW LNG’s parent company) has international experience rejuvenating LNGfacilities. A preliminary outline for facility decommissioning (to be fully developed near the end of theuseful life of the facility) includes the elements described in the following subheadings.

2.3.3.1 Dismantling Facility and Supporting Infrastructure

The LNG facility, pipelines, storage tanks and associated supporting infrastructure will bedecommissioned in accordance with the decommissioning plan. Current expectations are thatequipment that can be salvaged will be reused or resold. Where feasible, material that cannot beused for its original purpose will be recycled or scrapped, to reduce waste requiring disposal. All

waste generated throughout the decommissioning process will be sent to an approved offsite facility.The bridge and access road are considered permanent and decommissioning is not anticipated.

Prior to removal, equipment will be depressurized, purged and flushed of hydrocarbons and otherproducts to prevent uncontrolled releases of hydrocarbon materials.

A Phase II Contaminated Site Assessment will be undertaken prior to site refurbishment works toensure any contamination is not disturbed. Any contamination caused by the facility will beremediated in accordance with applicable regulations. Baseline Phase I and Phase II ContaminatedSite Assessments were completed in 2013.

2.3.3.2 Dismantling of Marine Terminal

The loading and unloading infrastructure on the marine terminal and MOF are expected to bedecommissioned in the similar fashion to the LNG facility. The terminal and MOF will likely remain inplace for future potential use on Lelu Island, subject to discussion and agreement with PRPA.

2.3.3.3 Waste Disposal

Waste associated with dismantling of the facility and terminal will be recycled or sent to an approvedoffsite facility.

2.3.3.4 Site Clean-up and Reclamation

Site clean-up and reclamation will be based on discussions with PRPA. This may involve preparationof the disturbed portion of Lelu Island for other industrial purposes or reclamation to restore

ecological values.


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2.4 Alternative Means of Carrying out the Project

Pursuant to Section 19(1)(g) of CEAA 2012, an assessment of alternative means of carrying out theProject is required. Alternative means of carrying out the Project that are economically and

technically feasible are discussed below along with general effects associated with such alternativemeans and the rational for selection of the preferred alternatives. The following alternatives wereassessed:

Alternative LNG production processes

Alternative main refrigerant compressor drivers

Alternative source of electrical power

Alternative land-based access to Lelu Island

Alternative site location

Alternative placement of marine infrastructure (trestle, berths and MOF)

Alternatives to disposal at sea of marine sediments Alternative locations for the disposal at sea of marine sediments

Alternative project site layout

Alternative construction camp locations.

2.4.1 Alternative LNG Production Processes

Three LNG production processes were considered:

The propane pre-cooled mixed refrigerant (C3MR) process Air Product and Chemical Inc.(ACPI)

The ConocoPhillips Optimized Cascade® process The Dual Mixed Refrigerant (DMR) process.

The C3MR process uses a propane heat exchanger for pre-cooling the gas followed by mixedrefrigerant cooling (nitrogen, ethane, propane, butane mixture) to liquefy the gas (see Figure 2-4).


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Figure 2-4: C3MR Liquefaction Process Block Diagram

The ConocoPhillips Optimized Cascade® process sequentially uses propane (or propylene),

ethylene, and methane as refrigerants. Like the APCI C3MR process, propane (or propylene) is used

to pre-cool the natural gas. The gas is cooled in an ethylene heat exchanger and finally, in two steps,to approximately -162°C and liquefied in the methane heat exchange (see Figure 2-5).


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Figure 2-5: ConocoPhillips Optimized Cascade® Liquefaction Process Block Diagram

For both processes, the natural gas is pre-cooled to -35°C using the propane (or propylene)

refrigerant. In the APCI C3MR process, the pre-cooled gas flows into the main cryogenic heatexchanger where it is liquefied and sub-cooled to -162°C by mixed refrigerant. In the ConocoPhillipsOptimized Cascade® process, the pre-cooled gas passes through a second heat exchanger thatuses ethylene as the refrigerant, and then a third heat exchanger that uses methane as therefrigerant and brings the temperature down to liquefy the gas (approximately -162°C).

The dual mixed refrigerant (DMR) technology is similar to the C3MR process. Instead of purepropane in the pre-cooling cycle, it uses another mixed refrigerant. This technology can be licensedfrom Shell or APCI.

2.4.1.1 Feasibility of Alternatives

Feasibility criteria for liquefaction processes were:

Pre-cooling systems appropriate to site ambient conditions

Proven systems for baseload facilities.

Only two baseload LNG facilities use mixed-refrigerant pre-cooling, and these are located in sitesthat experience large temperature variation and much lower ambient temperatures than experiencedon Lelu Island. This, coupled with familiarity and market share of C3MR and Optimized Cascadeprocess, ruled out DMR.


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2.4.1.2 Selection Criteria Assessment

Key differences between the two remaining liquefaction processes are the refrigerant gases used(pure propane and mixed gases for C3MR, pure gases for the Optimized Cascade process) and the

type of heat exchanger utilized (spiral wound for C3MR, plate fin for Optimized Cascade).The C3MR process is the most widely used on baseload LNG facilities, and has high thermodynamicefficiencies. The Optimized Cascade process currently has about 10% built market share, but willgrow when several large capacity projects in Australia come on stream in the next few years.

Differences between C3MR and Optimized Cascade are related to efficiency of the systems, andsubsequent differences in emissions; however, these differences in emissions are considered minor.The Air Quality and Greenhouse Gas Management VCs would be most affected by differencesbetween these options; however as the difference in emissions is very small, effects on these VCsare likely to be very similar for either option. Thus, final selection of a process will depend on adetailed economic and technical analysis of the full-facility designs presented by competing consortiaduring FEED.

2.4.1.3 Preferred Alternative

The final choice between C3MR and Optimized Cascade remains under evaluation; a decision willbe made after evaluation of FEED for the facility is complete.

2.4.2 Alternative Main Refrigerant Compressor Drivers

The liquefaction process requires 40 to 45 MW of power per MTPA of LNG production. The power isused predominantly in the main refrigerant compressor drivers. Potential driver types include:

Steam turbines

Heavy duty industrial gas turbines

Aero-derivative gas turbines Electric motors.

In all baseload LNG facilities, except one, the main compressor drivers are driven by steam turbinesor gas turbines. When expressed as production capacity, only 1% of LNG is produced by facilitiesusing electric motors as main compressor drivers. Steam turbine drivers, on the other hand are usedin plants that were built in the 1970s and 1980s, including Malaysia LNG Sdn. Bhd. (a PETRONASfacility). Figure 2-6 depicts the use of types of compressor drivers.


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Figure 2-6: LNG Production by Compressor Driver Type

The following discussion does not include projects currently under construction that are designedwith gas turbine drivers.

Steam turbine drivers require extensive water treatment and steam production facilities to be built onsite. These boilers operate in the gauge pressure range of 60 to 80 bar to generate steam at 500ºCto 600ºC. Steam quality is maintained by using high purity water treated with chemicals to preventcorrosion. A continuous bleed of steam and boiler water is required to manage buildup of thechemicals in the system. The use of steam boilers also requires a large amount of cooling water,usually drawn from and returned to the sea.

Gas turbine drivers are directly connected to compressors by rotating shafts. They combust naturalgas to produce mechanical drive power. Gas turbines can be classified into two categories: heavy-duty industrial types and aero-derivative types. The aero-derivative type is adapted from enginesused to propel large aircraft. However, the use of aero-derivative gas turbine to drive refrigerantcompressors in LNG services is still in its infancy. At present, fewer than five LNG plants use aero-derivative drivers. Heavy-duty industrial gas turbines have recorded a large number of running hoursand form the backbone of the LNG industry.

The use of electrical motors to drive large compressors has not been widely adopted. While electricalmotor can be reliable and does not directly emit greenhouse gases, they require a dedicated powerisland. The power island is usually gas-turbine based. Due to the lack of operating experience withlarge electrical motors in the LNG industry, some potential technical problems with such designsremain unresolved.

2.4.2.1 Feasibility of Alternatives

The key feasibility criterion for driver selection was avoidance of effects on the marine environment.

The Marine Resources VC would likely be affected by the steam turbine option. Steam turbines havea large demand for cooling water. Because of the potential effects on the marine environment fromdrawing and returning water near Lelu Island, steam turbines were determined by PNW LNG to notbe a feasible alternative.

Electric Motor

1%

Gas Turbine

77%

Steam Turbine

22%

Source : IHS CERA, March


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2.4.2.2 Selection Criteria Assessment

The choice of refrigerant compressor drivers were evaluated against following set of criteria in pre-FEED:

Environmental footprint Plant capacity requirements

Plot space availability

Availability and reliability of machines

Technical risks

Capital and operating cost (including carbon tax).

PNW LNG performed an internal study to evaluate the economic feasibility of driver types, whichweighted industrial machines with aero-derivative machines and motors. Environmental performanceof each option was considered in the economics but carbon tax was calculated as a penalty. The Air

Quality and Greenhouse Gas Management VCs would be most affected by differences inenvironmental performance of the different drivers, because of differences in emissions. The needfor a gas-powered source for electric drivers results in environmental effects of this option beingsimilar to the gas-turbine drivers. Based on specific machine types and design parameters, the aero-derivative configuration is found to provide marginally better economics, in part becaus

pacific northwest lng

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